Fluids containing cellulose fibers and cellulose nanoparticles for oilfield applications

ABSTRACT

A fluid for treating a subterranean formation includes a solvent, a rheology modifier, and a composition that includes a mixture of cellulose fibers and cellulose nanoparticles. The cellulose nanoparticles have a positive zeta potential in a range of about +100 mV to about +10 mV, and a length in a range of from about 50 nm to about 500 nm, and the cellulose fibers have a length from about 50 microns to about 500 microns.

CROSS-REFERENCE TO RELATED APPLICATION

This application is a division of U.S. Patent Application PublicationNo. 2017/0145285, filed on Nov. 22, 2016, which claims the benefit ofand priority to U.S. Provisional Patent Application No. 62/258,881,filed Nov. 23, 2015, the disclosure of which is hereby incorporated byreference.

BACKGROUND

Hydrocarbons (oil, natural gas, etc.) may be obtained from asubterranean geologic formation (a “reservoir”) by drilling a well thatpenetrates the hydrocarbon-bearing formation. Well treatment methodsoften are used to increase hydrocarbon production by using a chemicalcomposition or fluid, such as a treatment fluid.

Cellulose fibers and their derivatives constitute one of the mostabundant renewable polymer resources available on earth and can be usedin treatment methods for a variety of reasons, such as viscosifyingvarious fluids used in stimulation, drilling and cementing fluids.Cellulose fibers can be obtained from a cellulosic source, such as woodpulp, by known processes, some of which may break down and wash away thelignin (leaving behind the cellulose fibers, which may have an abundanceof hydroxyl groups). Further processing (mechanical or chemical) breaksthe cellulose fibers down into nanocellulose (such as NanoCrystallineCellulose (NCC) particles) and/or nanofibrils, which depending on theprocessing conditions may also have an abundance of hydroxyl groups.

Nanocelluloses, such as NCC particles, have the capability of forminginter and intra hydrogen bonding amongst the particles in water basedtreatment fluids. This network formation helps suspend particles withinthe treatment fluid. For treatment fluids containing nanocelluloses,suspension of the components of the fluid is able to take place above acertain threshold nanocellulose concentration (that is, a thresholdnanocellulose concentration), which is dependent on a variety offactors, such as, for example, the dimensions of the particles, andionic strength of the fluid. Below this threshold concentration,nanocelluloses, such as NCC particles, may lose their suspensioncapabilities, and thus to aid with suspension (for treatment fluidscontaining nanocellulose contents below the threshold concentration), anadditional component can be added to the treatment fluid.

SUMMARY

This summary is provided to introduce a selection of concepts that arefurther described below in the detailed description. This summary is notintended to identify key or essential features of the claimed subjectmatter, nor is it intended to be used as an aid in limiting the scope ofthe claimed subject matter.

In some embodiments, the present disclosure relates to method fortreating a subterranean formation, the method including combining arheology modifier, a mixture of cellulose nanoparticles and cellulosefibers, and a solvent to form a treatment fluid, where the cellulosenanoparticles have a negative zeta potential or a positive zetapotential, and a length in the range of from about 50 nm to about 500nm, and the cellulose fibers have a length of from about 10 microns toabout 500 microns; and introducing the treatment fluid into asubterranean formation.

In some embodiments, the present disclosure relates a fluid for treatinga subterranean formation, the fluid including a solvent, a rheologymodifier, and a composition including a mixture of cellulose fibers andcellulose nanoparticles, where the cellulose nanoparticles have anegative zeta potential, and a length in the range of from about 50 nmto about 500 nm, and the cellulose fibers have a length of from about 40microns to about 500 microns.

In some embodiments, the present disclosure relates a method ofcontrolling lost circulation in a subterranean formation or method fortreating a subterranean formation. The method may include contacting asubterranean formation with a treatment fluid including a solvent, acellulosic fiber, and a cellulose nanoparticle.

In some embodiments, the present disclosure relates to alost-circulation material including a cellulosic fiber, and a cellulosenanoparticle.

BRIEF DESCRIPTION OF THE DRAWINGS

Certain embodiments of the disclosure will hereafter be described withreference to the accompanying drawings, wherein like reference numeralsdenote like elements. It should be understood, however, that theaccompanying figures illustrate the various implementations describedherein and are not meant to limit the scope of various technologiesdescribed herein, and:

FIG. 1 shows an example of a white filter cake as a result of a test;

FIG. 2 shows no filter cake being formed as a result of a test; and

FIG. 3 shows sandstones cores as a result of a test.

DETAILED DESCRIPTION

In the following description, numerous details are set forth to providean understanding of the present disclosure. However, it may beunderstood by those skilled in the art that the methods of the presentdisclosure may be practiced without these details and that numerousvariations or modifications from the described embodiments may bepossible.

At the outset, it should be noted that in the development of any suchactual embodiment, numerous implementation-specific decisions may bemade to achieve the developer's specific goals, such as compliance withsystem related and business related constraints, which will vary fromone implementation to another. Moreover, it will be appreciated thatsuch a development effort might be complex and time consuming but wouldnevertheless be a routine undertaking for those of ordinary skill in theart having the benefit of this disclosure. In addition, the compositionused/disclosed herein can also comprise some components other than thosecited. In the summary and this detailed description, each numericalvalue should be read once as modified by the term “about” (unlessalready expressly so modified), and then read again as not so modifiedunless otherwise indicated in context. The term about should beunderstood as any amount or range within 10% of the recited amount orrange (for example, a range from about 1 to about 10 encompasses a rangefrom 0.9 to 11). Also, in the summary and this detailed description, itshould be understood that a range listed or described as being useful,suitable, or the like, is intended to include support for anyconceivable sub-range within the range at least because every pointwithin the range, including the end points, is to be considered ashaving been stated. For example, “a range of from 1 to 10” is to be readas indicating each possible number along the continuum between about 1and about 10. Furthermore, one or more of the data points in the presentexamples may be combined together, or may be combined with one of thedata points in the specification to create a range, and thus includeeach possible value or number within this range. Thus, (1) even ifnumerous specific data points within the range are explicitlyidentified, (2) even if reference is made to a few specific data pointswithin the range, or (3) even when no data points within the range areexplicitly identified, it is to be understood (i) that the inventorsappreciate and understand that any conceivable data point within therange is to be considered to have been specified, and (ii) that theinventors possessed knowledge of the entire range, each conceivablesub-range within the range, and each conceivable point within the range.Furthermore, the subject matter of this application illustrativelydisclosed herein suitably may be practiced in the absence of anyelement(s) that are not specifically disclosed herein.

The methods of the present disclosure relate to introducing treatmentfluids comprising a mixture of cellulose fibers and cellulosenanoparticles (such as nanocrystalline cellulose “NCC”) into asubterranean formation for an intended downhole operation. Unlessotherwise indicated, the term “cellulose fiber(s)” is usedinterchangeably with the term “cellulosic fiber(s)”, and the term “NCC”is used interchangeably with the term “NCC particle”.

In some embodiments, the cellulose fibers and cellulose nanoparticles(such as NCC) are present in the treatment fluids in amounts effectiveto create a type of synergy between the two components that enhances thesuspension capability of the treatment fluid such that suspension of,for example, particles (such as proppant) in the treatment fluids isable to take place at cellulose nanoparticle contents that wouldotherwise afford poor suspension capabilities. For example, in someembodiments, cellulose fibers and NCC particles may be present in thetreatment fluids in amounts effective to create a type of synergy thatenhances the suspension of, for example, particles (such as proppant) inthe treatment fluids to an extent a suspension can be achieved with asubstantially lower NCC particle content (in weight percent) relative toa fluid in which the cellulose fibers were absent but the othercomponents were the same (in other words, a treatment fluid where theNCC particles and the other components in the treatment fluid wouldexhibit a poor suspension capability (i.e., the majority of thecomponents would settle to the bottom of the fluid).

In some embodiments, the cellulose fibers and cellulose nanoparticles(such as NCC) are present in the treatment fluids in amounts effectiveto suspend particles (for example, proppant materials) in pores and/orfractures of subterranean formations.

In some embodiments, the amounts of the cellulose fibers and thecellulose nanoparticles (such as NCC) in the treatment fluids effectiveto prevent and/or reduce the loss of fluid circulation into thesubterranean formation.

The total amount (by weight percent (wt %) relative to the total weightof the treatment fluid, unless otherwise indicated) of the cellulosefibers and cellulose nanoparticles and relative amounts of each (thatis, the weight ratio of the cellulose fibers to the cellulosenanoparticles) to be included in the treatment fluids to achieve thedesired effect may depend on the desired application and/or downholeoperation, as well as on a number of other factors known to thoseskilled in the art, including, for example, the downhole equipment, andformation characteristics and conditions.

For example, in some embodiments, the fluids, treatment fluids, orcompositions of the present disclosure may contain a mixture ofcellulose fibers and cellulose nanoparticles in any effective amount(that is, the total amount including the weight of both the cellulosefibers and cellulose nanoparticles) to accomplish the intended downholeoperation, such as in an amount of from about 0.001 wt % to about 20 wt%, such as an amount of from about 0.01 wt % to about 10 wt %, or anamount of from about 0.1 wt % to about 5 wt %, or an amount of fromabout 0.5 wt % to about 2 wt % based on the total weight of the fluid,treatment fluid, or composition. The amount of the cellulose fibers(alone, not counting the cellulose nanoparticles) in the fluids,treatment fluids, or compositions of the present disclosure may be anamount of from about 0.001 wt % to about 10 wt %, such as an amount offrom about 0.01 wt % to about 10 wt %, or an amount of from about 0.1 wt% to about 5 wt %, or an amount of from about 0.5 wt % to about 2 wt %based on the total weight of the fluid, treatment fluid, or composition.In such embodiments, the amount of the cellulose nanoparticles (alone,not counting the cellulose fibers) in the fluids, treatment fluids, orcompositions of the present disclosure may be an amount of from about0.001 wt % to about 10 wt %, such as an amount of from about 0.01 wt %to about 10 wt %, or an amount of from about 0.1 wt % to about 5 wt %,or an amount of from about 0.5 wt % to about 2 wt % based on the totalweight of the fluid, treatment fluid, or composition.

In embodiments, the mixture of cellulose fibers and cellulosenanoparticles may include the cellulose fibers in an amount in the rangeof from about 0.1% to about 99.9% by weight based on the total weight ofthe mixture of the cellulose fibers and cellulose nanoparticles, orabout 1% to about 99% by weight based on the total weight of the mixtureof the cellulose fibers and cellulose nanoparticles, or about 5% toabout 95% by weight based on the total weight of the mixture of thecellulose fibers and cellulose nanoparticles, or about 15% to about 80%by weight based on the total weight of the mixture of the cellulosefibers and cellulose nanoparticles, or about 25% to about 50% by weightbased on the total weight of the mixture of the cellulose fibers andcellulose nanoparticles.

In embodiments, the mixture of cellulose fibers and cellulosenanoparticles may include the cellulose nanoparticles in an amount inthe range of from about 0.1% to about 99.9% by weight based on the totalweight of the mixture of the cellulose fibers and cellulosenanoparticles, or about 1% to about 99% by weight based on the totalweight of the mixture of the cellulose fibers and cellulosenanoparticles, or about 5% to about 95% by weight based on the totalweight of the mixture of the cellulose fibers and cellulosenanoparticles, or about 15% to about 80% by weight based on the totalweight of the mixture of the cellulose fibers and cellulosenanoparticles, or about 50% to about 75% by weight based on the totalweight of the mixture of the cellulose fibers and cellulosenanoparticles.

The treatment fluids comprising the cellulose fibers and cellulosenanoparticles of the present disclosure may be introduced during methodsthat may be applied at any time in the life cycle of a reservoir, fieldor oilfield; for example, the methods and treatment fluids of thepresent disclosure may be employed in any desired downhole application(such as, for example, stimulation, hydraulic fracturing, and cementing)at any time in the life cycle of a reservoir, field or oilfield. Forexample, the mixture of cellulose fibers and cellulose nanoparticles(such as NCC) may be included in a variety of fluids used insubterranean treatment methods for any desired downhole operation, suchas, for example, to provide lost-circulation control and/or provideparticle (such as proppant) suspension.

The term “treatment fluid,” refers to any fluid used in a subterraneanoperation in conjunction with a desired function and/or for a desiredpurpose. The term “treatment,” or “treating,” does not imply anyparticular action by the fluid. For example, a treatment fluid (such asa treatment fluid comprising a cellulose fiber and a cellulosenanoparticle, such as nanocrystalline cellulose (NCC)) introduced into asubterranean formation subsequent to a leading-edge fluid may be ahydraulic fracturing fluid, an acidizing fluid (acid fracturing, aciddiverting fluid), a stimulation fluid, a sand control fluid, acompletion fluid, a wellbore consolidation fluid, a remediationtreatment fluid, a cementing fluid, a drilling fluid, a spacer fluid, afrac-packing fluid, or gravel packing fluid. The methods of the presentdisclosure in which a treatment fluid comprising a mixture of acellulose fiber and a cellulose nanoparticle (such as a NCC particle)may be used in full-scale operations, pills, or any combination thereof.As used herein, a “pill” is a type of relatively small volume speciallyprepared treatment fluid, such as a treatment fluid comprising acellulose nanoparticle where the fluid exhibits a viscosity/yield stressincrease resulting from the addition of the cellulose fiber andcellulose nanoparticle, placed or circulated in the wellbore.

The term “fracturing” refers to the process and methods of breaking downa geological formation, such as the rock formation around a wellbore,and creating a fracture by pumping fluid at very high pressures(pressure above the determined closure pressure of the formation), inorder to increase production rates from or injection rates into ahydrocarbon reservoir. The fracturing methods of the present disclosuremay include a treatment fluid comprising a cellulose fiber and acellulose nanoparticle, such as a NCC particle, but otherwise useconventional techniques known in the art.

In embodiments, the treatment fluids of the present disclosure may beintroduced into a wellbore. A “wellbore” may be any type of well,including, for example, a producing well, a non-producing well, aninjection well, a fluid disposal well, an experimental well, anexploratory well, and the like. Wellbores may be vertical, horizontal,deviated some angle between vertical and horizontal, and combinationsthereof, for example a vertical well with a non-vertical component.

The term “field” includes land-based (surface and sub-surface) andsub-seabed applications. The term “oilfield,” as used herein, includeshydrocarbon oil and gas reservoirs, and formations or portions offormations where hydrocarbon oil and gas are expected but mayadditionally contain other materials such as water, brine, or some othercomposition.

The term “treating temperature,” refers to the temperature of thetreatment fluid that is observed while the treatment fluid is performingits desired function and/or desired purpose.

The term “cellulose nanoparticle” refers, for example, to one or morecellulose nanoparticles, such as a NCC particle, that have anaggregation or interaction tendency either with each other and/or withthe cellulose fibers and/or one or more of the additives in thefluid/system. Suitable cellulose nanoparticles may include thosedescribed in U.S. Application Publication No. 2013/0274149, thedisclosure of which is incorporated by reference herein in its entirety.

In some embodiments, when an effective amount of the cellulose fibersand the cellulose nanoparticles are placed in treatment fluids, such asfracturing fluids, the cellulose fibers and the cellulose nanoparticleswill start forming aggregated structures and/or networks, and mayincrease the viscosity and yield stress of the fluids and systems, asdesired. Such aggregation may be driven by various factors and forces,such as, for example, hydrogen bonds, concentration effects,electrostatic forces and van der Waals forces. For example, in someembodiments, the surfaces of neighboring cellulose fibers and/orcellulose nanoparticles may be attracted and/or bound together byhydrogen bonds in aqueous media due to the complementary functionalgroups on the surface of the cellulose fibers and/or cellulosenanoparticles. Such complementary functional groups may be introduced bysurface-functionalizing the surface (or portions of the surface) of thecellulose fibers and/or cellulose nanoparticles.

The surface of the cellulose nanoparticles (and/or the cellulose fibers)may be modified (for example, surface-functionalized) in a manner thatis effective to ensure an at least temporary particle suspensioncapability and/or the onset of the formation of a gel network (forexample, a colloidal suspension with the cellulose fibers), which mayincrease the viscosity of the treatment fluid to a level that is desiredfor completing the intended downhole operation.

The term “surface-functionalizing” refers, for example, to the processof attaching (via a covalent or ionic bond) a functional group orchemical moiety onto a surface of a cellulose material, such ascellulose fiber and/or cellulose nanoparticle (a NCC particle). Suchfunctionalizing may be by esterification, etherification, acetylation,silylation, oxidation, or functionalization with various other chemicalmoieties, such as a hydrophobic group, hydroxyls, sulfate esters,carboxylates, phosphates, halides, ethers, aldehydes, ketones, esters,amines, amides and/or various chemicals containing such groups.

The phrase “surface of the cellulose nanoparticle” or “surface of thecellulose fiber” refers, for example, to the outer circumferential areasof a cellulose material (that is either the nanoparticle or fiber,respectively), such as, for example, outer circumferential areas of acellulose nanoparticle, such as a NCC particle, that contains moietiesthat are suitable to participate in chemical reactions.

The term “moiety” and/or “moieties” refer, for example, to a particularfunctional group or part of a molecule, such as, for example, theclosely-packed hydroxyl moieties on the surface of a cellulose material,such as, for example, a cellulose nanoparticle (such as NCC).

The term “surface modifier” refers, for example, to a substance, such asa chemical moiety, that attaches or is attached onto a surface of acellulose material, such as, for example, a cellulose nanoparticle (suchas NCC). Such attachment may be by esterification, etherification,acetylation, silylation, oxidation, grafting polymers on the surface,functionalization with various chemical moieties (such as with ahydrophobic group), and noncovalent surface modification, such asadsorbing surfactants, which may interact via a hydroxyl group, sulfateester group, carboxylate groups, phosphates, halides, ethers, aldehydes,ketones, esters, amines and/or amides.

Cellulose

In embodiments, any suitable cellulose fibers and cellulosenanoparticles (such as nanocrystalline cellulose (NCC)) may be comprisedin the treatment fluids of the present disclosure. For example, suchcellulose materials may include those having a surface that may bemodified (and/or temporarily modified) in a manner (such as, forexample, by conferring a negative zeta potential to the cellulosematerials), that assists in the suspension of particles (such asproppant(s)) for a predetermined duration in a treatment fluid, such asvia the formation of a gel network. Alternatively, the cellulosematerials may be surface modified to have positive zeta potential.

The cellulosic fiber may be derived from any suitable cellulose source,such as from a variety of plant products, including, for example, woodpulp, fiber from trees, plants, sugar beets, sugar cane, citrus pulp,potatoes, grains, peanut hulls, corn cobs, tobacco stems, apple pumice,natural grasses, cotton, and peat. In some embodiments, the cellulosicfibers may be obtained by extraction from one or more different types ofwood pulp.

In some embodiments, mechanically derived cellulosic fiber may not bechemically treated and/or chemically modified before being introducedinto the treatment fluids of the present disclosure.

In embodiments, the cellulosic fibers included in the treatment fluidsof the present disclosure may have any suitable length for completingthe intended downhole operation, such as, for example, a length in arange of from about 20 μm to about 1000 μm, such as a length in a rangeof from about 50 μm to about 500 μm, or a length in a range of fromabout 100 μm to about 250 μm. In embodiments, the average length of thecellulosic fibers included in the treatment fluids of the presentdisclosure may be in a range of from about 40 μm to about 300 μm, suchas an average length in a range of from about 75 μm to about 200 μm, oran average length of from about 100 μm to about 150 μm. The lengths ofthe fibers may vary depending on whether the fibers are measured in adry or wet state. It should be understood that a fiber may elongateslightly when the fiber is wet. Unless specified otherwise, thedisclosed fiber lengths are not specific to a wet or dry fiber andeither wet or dry fibers, or both, may fall within the specified range.

In embodiments, the diameter of the cellulosic fibers included in thetreatment fluids may be any suitable diameter for completing theintended downhole operation, such as a diameter in a range of from about2 μm to about 100 μm, such as a diameter in a range of from about 10 μmto about 80 μm, or from about 15 to about 60 μm. In embodiments, theaverage diameter of the cellulosic fibers included in the treatmentfluids may be a diameter in a range of from about 5 μm to about 60 μm,such as an average diameter in a range of from about 10 μm to about 50μm, or an average diameter in a range of from about 15 to about 40 μm.In embodiments, the cellulosic fibers may have any suitable aspect ratiofor completing the intended downhole operation, such as an aspect ratio(length:diameter) in a range of from about 1 to about 100, such as fromabout 1 to about 50, or from about 1 to about 20.

In embodiments, the cellulose nanoparticles may have a length in a rangeof from about 50 nm to about 500 nm, such as in a range of from about 70to about 300 nm, or in a range of from about 80 to about 100 nm. In suchembodiments, the NCC particles may have a diameter in a range of fromabout 2 to about 50 nm, such as in a range of from about 4 to about 20nm, or in a range of from about 5 to about 10 nm. In embodiments, theNCC particles may have an aspect ratio (length:diameter) of from about 5to about 100, such as from about 25 to about 100, or from about 50 toabout 75.

In some embodiments, the cellulose nanoparticles may have any desiredcomposition/functionalities, which may vary depending on the fabricationmethod and/or the source of particles. In embodiments, the cellulosenanoparticles may be selected to ensure the formation and/or the onsetof the formation of a gel network in the presence of a predeterminedamount of cellulose fiber such that the fluid exhibits an increase inviscosity that is sufficient to suspend at least 80%, such as at least90%, or at least 99% of the particulate materials (such as proppantmaterials) present in the treatment fluid.

In some embodiments, the cellulose nanoparticles that may be used in themethods of the present disclosure include the nanocellulose materialsthat are described in U.S. Application Publication No. 2013/0274149, thedisclosure of which is incorporated by reference herein in its entirety.For example, three suitable types of such nanocellulose materials arecalled nanocrystalline cellulose (NCC), microfibrillated cellulose(MFC), and bacterial cellulose (BC). Additional details regarding thesematerials are described in U.S. Pat. Nos. 4,341,807, 4,374,702,4,378,381, 4,452,721, 4,452,722, 4,464,287, 4,483,743, 4,487,634 and4,500,546, the disclosures of each of which are incorporated byreference herein in their entirety.

Briefly, suitable nanocellulose materials may have a repetitive unit ofβ-1,4 linked D glucose units, as seen in the following chemicalstructure:

The integer values for the variable n relate to the length of thenanocellulose chains, which generally depends on the source of thecellulose and even the part of the plant containing the cellulosematerial.

Nanocrystalline cellulose (NCC), also referred to as cellulosenanocrystals, cellulose whiskers, or cellulose rod-like nanocrystals,may be obtained from cellulose fibers. Cellulose nanocrystals may havedifferent shapes besides rods. Examples of these shapes include anynanocrystal in the shape of a 4-8 sided polygon, such as, a rectangle,hexagon or octagon. NCCs are generally made via the hydrolysis ofcellulose fibers from various sources such as cotton, wood, wheat strawand cellulose from algae and bacteria. These cellulose fibers arecharacterized in having two distinct regions, an amorphous region and acrystalline region. In embodiments, the cellulose nanoparticles mayinclude NCC prepared through acid hydrolysis of the amorphous regions ofcellulose fibers that have a lower resistance to acid attack as comparedto the crystalline regions of cellulose fibers. In some embodiments, thecellulose nanoparticles may include NCC particles with “rod-like” shapes(herein after referred to as “rod-like nanocrystalline celluloseparticles” or more simply “NCC particles”) having a crystallinestructure.

In some embodiments, NCC particles with “rod-like” shapes (herein afterreferred to as “rod-like nanocrystalline cellulose particles” or moresimply “NCC particles”) having a crystalline structure may be comprisedin the treatment fluid of the present disclosure along with thecellulosic fibers.

In some embodiments, the degree of crystallinity can vary from about 50%to about 95%, such as from about 65% to about 85%, or about 70% to about80% by weight of the NCC particles. In some embodiments, the degree ofcrystallinity is from about 85% to about 95% such as from about 88% toabout 95% by weight NCC particles.

Techniques that may be used to determine NCC particle size are scanningelectron microscopy (SEM), transmission electron microscopy (TEM) and/oratomic force microsocopy (AFM). Wide angle X-ray diffraction (WAXD) maybe used to determine the degree of crystallinity.

Nanofibrillated cellulose (NFC) or Micro Fibrillated Cellulose (MFC), ornanofibrils (collectively hereinafter referred to as “MFC”), may also beused in the methods of the present disclosure. MFC is a form ofnanocellulose derived from wood products, sugar beet, agricultural rawmaterials or waste products may also be used in the methods of thepresent disclosure. In MFC, the individual microfibrils have beenincompletely or totally detached from each other. For example, themicrofibrillated cellulose material may have an average diameter in arange of from about 5 nm to about 500 nm, such as in a range of fromabout 5 nm to about 250 nm, or in a range of from about 10 nm to about100 nm. In some embodiments, the microfibrillated cellulose material mayhave an average diameter of from about 10 nm to about 60 nm.Furthermore, in MFC, the length may be up to 1 μm, such as from about500 nm to about 1 μm, or from about 750 nm to about 1 μm. The ratio oflength (L) to diameter (d) of the MFC may be from about 10 to about 200,such as from about 75 to about 150, or from about 100 to about 150.

One common way to produce MFC is the delamination of wood pulp bymechanical pressure before and/or after chemical or enzymatic treatment.Additional methods include grinding, homogenizing, intensification,hydrolysis/electrospinning and ionic liquids. Mechanical treatment ofcellulosic fibers is very energy consuming and this has been a majorimpediment for commercial success. Additional manufacturing examples ofMFC are described in WO 2007/091942, WO 2011/051882, U.S. Pat. No.7,381,294 and U.S. Patent Application Pub. No. 2011/0036522, each ofwhich is incorporated by reference herein in their entirety.

Bacterial nanocellulose may also be used in the methods of the presentdisclosure. Bacterial nanocellulose is a material obtained via abacterial synthesis from low molecular weight sugar and alcohol forinstance. The diameter of this nanocellulose is found to be about 20-100nm in general. Characteristics of cellulose producing bacteria andagitated culture conditions are described in U.S. Pat. No. 4,863,565,the disclosure of which is incorporated by reference herein in itsentirety. Bacterial cellulose nanoparticles are microfibrils secreted byvarious bacteria that have been separated from the bacterial bodies andgrowth medium. The resulting microfibrils are microns in length, have alarge aspect ratio (greater than 50) with a morphology depending on thespecific bacteria and culturing conditions.

While the discussion below identifies NCC particles as the particularcellulose nanoparticle being modified, other cellulose nanoparticlematerials identified above may also be used.

In embodiments, modification/functionalization, such as surface-onlymodification, may be used to tailor the surface of a cellulosenanoparticle to form cellulose nanoparticle having a charged surface(for example, with a quantifiable zeta potential, such as a negativezeta potential, which, for example, may be in the range of from about−100 mV to about −10 mV, or in the range of from about −80 mV to about−30 mV, or in the range of from about −60 mV to about −40 mV, or such asa positive zeta potential, for example, in the range of about +100 mV toabout +10 mV, or in the range of from about +80 mV to about +30 mV, orin the range of from about +60 mV to about +40 Mv). Such surface-onlymodification may be performed by a variety of methods, including, forexample, functionalization with various anionic groups/chemicalmoieties, as desired.

In some embodiments, the NCC particle surfaces may have a percentsurface functionalization of about 5 to about 90 percent, such as fromof about 25 to about 75 percent, and or of about 40 to about 60 percent.In some embodiments, about 5 to about 90 percent of the hydroxyl groupson NCC particle surfaces may be chemically modified, 25 to about 75percent of the hydroxyl groups on NCC particle surfaces may bechemically modified, or 40 to about 60 percent of the hydroxyl groups onNCC particle surfaces may be chemically modified.

In some embodiments, a negative zeta potential may be conferred to theNCC particle surface by attaining a percent surface functionalizationwith suitable anionic functional groups (such as, for example, carboxylgroups or sulfate groups), of about 5 to about 90 percent surfacefunctionalization, such as from of about 25 to about 75 percent surfacefunctionalization, and or of about 40 to about 60 percent surfacefunctionalization. In some embodiments, about 5 to about 90 percent ofthe hydroxyl groups on NCC particle surface may be chemically modifiedto be suitable anionic functional groups, such as, for example, carboxylgroups or sulfate groups; or 25 to about 75 percent of the hydroxylgroups on NCC particle surfaces may be chemically modified to be asuitable anionic functional groups, such as, for example, carboxylgroups or sulfate groups; or 40 to about 60 percent of the hydroxylgroups on NCC particle surfaces may be chemically modified to becarboxyl groups. In some embodiments the primary alcohols arefunctionalized. In some embodiments not all alcohols are functionalized(e.g., secondary alcohols). In some embodiments only the primaryalcohols are functionalized.

In some embodiments, a positive zeta potential may be conferred to theNCC particle surface by attaining a percent surface functionalizationwith suitable cationic functional groups (such as, for example, ammoniumor amine groups), of about 5 to about 90 percent surfacefunctionalization, such as from of about 25 to about 75 percent surfacefunctionalization, and or of about 40 to about 60 percent surfacefunctionalization. In some embodiments, about 5 to about 90 percent ofthe hydroxyl groups on NCC particle surface may be chemically modifiedto be suitable cationic functional groups, such as, for example,carboxyl groups or sulfate groups; or 25 to about 75 percent of thehydroxyl groups on NCC particle surfaces may be chemically modified tobe a suitable cationic functional groups, such as, for example, aminegroups; or 40 to about 60 percent of the hydroxyl groups on NCC particlesurfaces may be chemically modified to be amine groups.

Fourier Transform Infrared (FT-IR) and Raman spectroscopies and/or otherknown methods may be used to assess percent surface functionalization,such as via investigation of vibrational modes and functional groupspresent on the NCC particles. Additionally, analysis of the localchemical composition of the cellulose, NCC particles may be carried outusing energy-dispersive X-ray spectroscopy (EDS). The bulk chemicalcomposition can be determined by elemental analysis (EA). Zeta potentialmeasurements can be used with known instruments (such as, for example,with a Malvern 3000 Zetasizer) to determine the surface charge anddensity. Thermal gravimetric analysis (TGA) and differential scanningcalorimetry (DSC) can be employed to understand changes in heat capacityand thermal stability.

The selection of specific chemicals and functional groups for surfacemodification and/or functionalization, and the extent of the surfacemodification and/or functionalization of cellulose nanoparticles willdepend on a number of factors, such as, for example, the composition andpH of the treatment fluid, the downhole operation, the desired durationof the hindered aggregation or interaction tendency, and the temperatureat which the particles are to be used.

In some embodiments, the NCC particle surfaces may have a percentsurface functionalization with ionized surface groups of about 5 toabout 90 percent, such as from of about 25 to about 75 percent, and orof about 40 to about 60 percent. In some embodiments, about 5 to about90 percent of the hydroxyl groups on NCC particle surfaces may bechemically modified with ionized surface groups, 25 to about 75 percentof the hydroxyl groups on NCC particle surfaces may be chemicallymodified with ionized surface groups, or 40 to about 60 percent of thehydroxyl groups on NCC particle surfaces may be chemically modified withionized surface groups.

In some embodiments, the surface of the NCC particles may be modified,such as by removing at least some of the charged surface moieties thatmay be present on the particles, and introducing various surfacemodifiers, functional groups, species and/or molecules that eitherenhance or minimize aggregation and/or flocculation of the NCC particleswhen dispersed in a solvent, such as an aqueous solvent.

The amount of the cellulose fibers and cellulose nanoparticles (such asNCC) to be included in the treatment fluids of the present disclosuremay depend on a number of factors, including formation characteristicsand conditions, the downhole equipment, the desired application, andother factors known to those skilled in the art. In some embodiments,the cellulose fibers and cellulose nanoparticles (such as NCC) may beincluded in the treatment fluid in an amount of from about 2 pounds toabout 100 pounds per barrel of the fluid, such as in an amount of fromabout 4 pounds to about 60 pounds per barrel of the treatment fluid, orin an amount of from about 6 pounds to about 40 pounds per barrel of thetreatment fluid.

Applications

As discussed above, in embodiments, the methods of the presentdisclosure relate to the use of a mixture of cellulose fibers andcellulose nanoparticles in multiple oilfield applications. For example,the mixture of cellulose fibers and cellulose nanoparticles of thepresent disclosure may be used as an additive in conventional welltreatment fluids used in fracturing, cementing, sand control, shalestabilization, fines migration, drilling fluid, friction pressurereduction, loss circulation, well clean out, and the like. In someembodiments, the fluids, treatment fluids, or compositions of thepresent disclosure may comprise one or more separate types of mixturesof cellulose fibers and cellulose nanoparticles for the above-mentioneduses in an amount of from about 0.001 wt % to about 10 wt %, such as,about 0.01 wt % to about 10 wt %, about 0.1 wt % to about 5 wt %, or offrom about 0.5 wt % to about 5 wt % based on the total weight of thefluid, treatment fluid, or composition.

For example, the mixtures of cellulose fibers and cellulosenanoparticles of the present disclosure may also be used in welltreatment fluids as, for example, a viscosifying agent, proppanttransport agent, a material strengthening agent (such as for structuralreinforcement for cementing), a fluid loss reducing agent, frictionreducer/drag reduction agent and/or gas mitigation agent. Surfacemodification of the cellulose fibers and cellulose nanoparticles may beemployed to enhance or attenuate one or more of the properties of thecellulose fibers and cellulose nanoparticles in conjunction with theabove uses, as desired.

Regarding cementing, the mixture of cellulose fibers and cellulosenanoparticles may be used to stabilize foamed cement slurry, as anadditive for cement composite, to mitigate gas migration, to stabilizecement slurries and/or as an additive to reinforce a wellbore and/or acement column. Surface modification of the cellulose fibers andcellulose nanoparticles may be employed to enhance or attenuate one ormore of the properties of the cellulose nanoparticles in conjunctionwith the above uses, as desired.

In some embodiments, the mixture of cellulose fibers and cellulosenanoparticles may be incorporated into a spacer fluid, which is pumpedbetween the mud and cement slurry to prevent contamination. The mixtureof cellulose fibers and cellulose nanoparticles may be added to increaseand/or maintain an effective viscosity to prevent the mud mixing withthe cement.

In another embodiment, the mixture of cellulose fibers and cellulosenanoparticles may be used to increase the thermal stability of polymerfluids, such as those fluids that contain viscoelastic surfactant (VES).Surface modification of the cellulose fibers and cellulose nanoparticles(such as, for example, increasing or decreasing the charge density orthe type of charge (anionic or cationic) on the surface of the cellulosenanoparticles) may be employed to enhance or attenuate one or more ofthe properties of the mixture of cellulose fibers and cellulosenanoparticles in conjunction with the above uses, as desired.

In another embodiment, the mixture of cellulose fibers and cellulosenanoparticles may be used to improve the transport and the suspension ofvarious solid materials often included in the above well treatmentfluids, to transport pill materials, proppant and gravel. Surfacemodification of the cellulose nanoparticles may be employed to enhanceor attenuate one or more of the properties of the cellulosenanoparticles in conjunction with the above uses, as desired.

In another embodiment, the mixture of cellulose fibers and cellulosenanoparticles may be used to increase the viscosity of aqueous fluidsand non-aqueous based fluids (i.e., oil-based fluids) in a time orcondition dependent manner. In some embodiments, the fluids, treatmentfluids, or compositions of the present disclosure may comprise one ormore independent mixtures of cellulose fibers and cellulosenanoparticles for the above-mentioned uses in an amount of from about0.001 wt % to about 10 wt %, such as, 0.01 wt % to about 10 wt %, about0.1 wt % to about 5 wt %, or of from about 0.5 wt % to about 5 wt %based on the total weight of the fluid, treatment fluid, or composition.

The appropriate components and methods of patents and patent applicationpublications (e.g., identified in the present disclosure) may beselected for the present disclosure in embodiments thereof. Methods andfluids for fracturing an unconsolidated formation that includesinjection of consolidating fluids, as disclosed in U.S. Pat. No.6,732,800, the disclosure of which is herein incorporated by referencein its entirety. Techniques and fluids for the stimulation of very lowpermeability formations, as disclosed in U.S. Pat. No. 7,806,182, thedisclosure of which is herein incorporated by reference in its entirety.Techniques and fluids for fluid-loss control in hydraulic fracturingoperations and/or controlling lost circulation are known in the art, asdisclosed in U.S. Pat. Nos. 7,482,311, 7,971,644, 7,956,016, and8,381,813 the disclosures of which are herein incorporated by referencein their entireties. Fracturing fluids using degradable polymers asviscosifying agents, as disclosed in U.S. Pat. No. 7,858,561, thedisclosure of which is herein incorporated by reference in its entirety.Conventional fracturing fluid breaking technologies and the design offracturing treatments as described in U.S. Pat. No. 7,337,839, thedisclosure of which is hereby incorporated by reference in its entirety.Techniques and fluids for gravel packing a wellbore penetrating asubterranean formation, as disclosed in U.S. Pat. Nos. 8,322,419 and8,490,697, and U.S. Patent Application Publication Nos. 2015/0308238;2015/0198016; 2014/0014337; 2012/0048547; 2010/0096130; 2010/0314109;20100018709; 2010/0139919; 2008/0128129; and 2005/0028978, thedisclosures of which are hereby incorporated by reference in theirentireties. Techniques and fluids for providing sand control within awell are known in the art, as disclosed in U.S. Pat. No. 6,752,206, thedisclosure of which is herein incorporated by reference in its entirety.Techniques and compositions for drilling or cementing a wellbore areknown in the art, as disclosed in U.S. Pat. No. 5,518,996, thedisclosure of which is herein incorporated by reference in its entirety.The following are some of the known methods of acidizing hydrocarbonbearing formations which can be used as part of the present method: U.S.Pat. Nos. 3,215,199; 3,297,090; 3,307,630; 2,863,832; 2,910,436;3,251,415; 3,441,085; and 3,451,818, the disclosures of which are herebyincorporated by reference in their entireties.

Known methods, fluids, systems and compositions, such as those disclosedin the patents and patent application publications identified above, maybe modified to incorporate a mixture of cellulose fibers and cellulosenanoparticles; or a mixture of cellulose fibers and cellulosenanoparticles may be used as a substitute for one or more components,such as, for example, a viscosifying agent, a proppant transport agent,a material strengthening agent, a fluid loss reducing agent, a frictionreducer/drag reduction agent, a gas mitigation agent an additive for acement composite, and/or as an additive to reinforce a wellbore and/or acement column, disclosed in the patents identified above.

In embodiments, the mixture of cellulose fibers and cellulosenanoparticles added to such known fluids and/or compositions either in apre-hydrated form in water, such as deionized water, or directly to suchknown fluids and/or compositions as a powder.

While the methods and treatment fluids of the present disclosure aredescribed herein as comprising a mixture of cellulose fibers andcellulose nanoparticles, it should be understood that the methods andfluids of the present disclosure may optionally comprise otheradditional materials, such as the materials and additional componentsdiscussed in the aforementioned patents.

In some embodiments, the mixture of cellulose fibers and cellulosenanoparticles may be pumped with a particulate material, such asproppant, such that the mixture of cellulose fibers and cellulosenanoparticles are uniformly mixed with the particulate material. In someembodiments, a dispersion of the mixture of cellulose fibers andcellulose nanoparticles and the proppant may be introduced, such as bypumping, into the subterranean formation. The terms “dispersion” and“dispersed” refer, for example, to a substantially uniform distributionof components in a mixture. In some embodiments, a dispersed phase ofone or more mixtures of cellulose fibers and cellulose nanoparticles,and particulate material may be formed at the surface. An action orevent occurring “at the surface” refers, for example, to an action orevent that happens above ground, that is, not at an undergroundlocation, such as within the wellbore or within the subterraneanformation.

In some embodiments, the mixture of cellulose fibers and cellulosenanoparticles may be mixed and dispersed throughout the entire batch ofproppant to be pumped into the wellbore during the treatment operation.This may occur by adding the cellulose fibers and cellulosenanoparticles (either separately or as a mixture) to the proppant beforeit is mixed with the treatment fluid, adding the mixture of cellulosefibers and cellulose nanoparticles to the treatment fluid before it ismixed with the proppant, or by adding a slurry of mixture of cellulosefibers and cellulose nanoparticles at some other stage, such as eitherbefore the slurry is pumped downhole, or at a location downhole.

In some embodiments, the methods of the present disclosure may includethe following actions, in any order: placing a treatment fluid includinga mixture of cellulose fibers and cellulose nanoparticles and aparticulate material into a subterranean formation via a wellbore;mixing the treatment fluid to form an association, such as a covalentassociation and/or non-covalent association, of the mixture of cellulosefibers and cellulose nanoparticles with the particulate material,wherein the mixture of cellulose fibers and cellulose nanoparticlesoptionally form an association, such as a covalent association and/ornon-covalent association, with one or more particulate materials. Theterms “placing” or “placed” refer to the addition of a treatment fluidto a subterranean formation by any suitable means and, unless statedotherwise, do not imply any order by which the actions occur. The term“introduced” refers when used in connection with the addition of atreatment fluid to a subterranean formation may imply an order ofaccomplishing the recited actions, if not stated otherwise.

In some embodiments, the association may be a non-covalent (and/orcovalent) association in which one or more covalent bonds and/or one ormore non-covalent bonds (such as an ionic bond, hydrogen bond or van derWaals forces) between the cellulose fibers and/or cellulosenanoparticles and/or a particulate material, such as a proppant orcoated proppant, arise.

In some embodiments, the slurry of proppant and the mixture of cellulosefibers and cellulose nanoparticles may be pumped into the wellboreduring a portion of the treatment operation, for example, as the lastabout 5 to about 25% of the proppant is placed into the fracture, suchas to control flowback without using vast amounts of the mixture ofcellulose fibers and cellulose nanoparticles. Such a slug may also bepumped into the wellbore at other stages, for example, to provide anabsorbed scale inhibitor to be pumped to the front of the fracture.

In some embodiments, small slugs of a slurry of proppant and the mixtureof cellulose fibers and cellulose nanoparticles may be pumped in betweenslugs of slurry of proppant, or small slugs of a slurry of the mixtureof cellulose fibers and cellulose nanoparticles may be pumped betweenslugs of a proppant slurry. Such a series of stages may be used tocontrol flow dynamics down the fracture, for example, by providing moreplug flow-like behavior. Pumping of small slugs of slurry of the mixtureof cellulose fibers and cellulose nanoparticles as the tail-in is anexample of this type of procedure in a treatment operation.

In embodiments, a slurry of a mixture of proppant, cellulose fibers andcellulose nanoparticles may be used for any desired reason in the entirerange of reservoir applications, such as from fracturing to sandcontrol, frac-and-sand-pack and/or high permeability stimulation. Forexample, the methods of the present disclosure may be used in fluid lossapplications.

The treatment fluid carrying the mixture of cellulose fibers andcellulose nanoparticles may be any well treatment fluid, such as a fluidloss control pill, a water control treatment fluid, a scale inhibitiontreatment fluid, a fracturing fluid, a gravel packing fluid, a drillingfluid, and a drill-in fluid. The carrier solvent (or carrier fluid) forthe treatment fluid may be a pure solvent or a mixture. Suitablesolvents for use with the methods of the present disclosure, such as forforming the treatment fluids disclosed herein, may be aqueous or organicbased. Aqueous solvents may include at least one of fresh water, seawater, brine, mixtures of water and water-soluble organic compounds andmixtures thereof. Organic solvents may include any organic solvent thatis able to dissolve or suspend the various components, such as thechemical entities and/or components of the treatment fluid.

In some embodiments, the carrier fluid may be a low viscosity fluid,such as slickwater, which may or may not contain a viscosifying agent,and a sufficient amount of a friction reducing agent, such as, forexample, to minimize tubular friction pressures. In some embodiments,treatment fluids comprising a slickwater carrier fluid may have aviscosity that is slightly higher than unadulterated fresh water orbrine.

As discussed in more detail below, a mixture of cellulose fibers andcellulose nanoparticles may perform a variety of intended functions whenpresent in a treatment fluid, a few of which are illustrated in moredetail below.

Fracturing Fluids

The fluids and/or methods of the present disclosure may be used forhydraulically fracturing a subterranean formation. Techniques forhydraulically fracturing a subterranean formation are known to personsof ordinary skill in the art, and involve pumping a fracturing fluidinto the borehole and out into the surrounding formation. The fluidpressure is above the minimum in situ rock stress, thus creating orextending fractures in the formation. See Stimulation EngineeringHandbook, John W. Ely, Pennwell Publishing Co., Tulsa, Okla. (1994),U.S. Pat. No. 5,551,516 (Normal et al.), “Oilfield Applications,”Encyclopedia of Polymer Science and Engineering, vol. 10, pp. 328-366(John Wiley & Sons, Inc. New York, N.Y., 1987) and references citedtherein.

In some embodiments, hydraulic fracturing involves pumping aproppant-free viscous fluid, or pad—such as water with some fluidadditives to generate high viscosity—into a well faster than the fluidcan escape into the formation so that the pressure rises and the rockbreaks, creating artificial fractures and/or enlarging existingfractures. Then, proppant particles are added to the fluid to formslurry that is pumped into the fracture to prevent it from closing whenthe pumping pressure is released. In the fracturing treatment, fluids ofare used in the pad treatment, the proppant stage, or both.

In some embodiments, the fluids and/or methods of the present disclosuremay be employed during a first stage of hydraulic fracturing, where afluid is injected through wellbore into a subterranean formation at highrates and pressures. In such embodiments, the fracturing fluid injectionrate exceeds the filtration rate into the formation producing increasinghydraulic pressure at the formation face. When the pressure exceeds apredetermined value, the formation strata or rock cracks and fractures.The formation fracture is more permeable than the formation porosity.

In some embodiments, the fluids and/or methods of the present disclosuremay be employed during a later stage of hydraulic fracturing, such aswhere proppant is deposited in the fracture to prevent it from closingafter injection stops. In embodiments, the proppant may be coated with acurable resin activated under downhole conditions. Different materials,such as bundles of fibers, or fibrous or deformable materials, may alsobe used in conjunction with the mixture of cellulose fibers andcellulose nanoparticles to retain proppants in the fracture. The mixtureof cellulose fibers and cellulose nanoparticles and other materials,such as optional additional fibers, may form a three-dimensional networkwith the proppant, reinforcing it and limiting its flowback. At times,due to weather, humidity, contamination, or other environmentaluncontrolled conditions, some of these materials can aggregate and/oragglomerate, making it difficult to control their accurate delivery towellbores in well treatments.

In some embodiments, the amount of the cellulose fibers (alone, notcounting the cellulose nanoparticles) in the fluids, treatment fluids,or compositions of the present disclosure may be an amount of from about0.001 wt % to about 10 wt %, such as an amount of from about 0.01 wt %to about 10 wt %, or an amount of from about 0.1 wt % to about 5 wt %,or an amount of from about 0.5 wt % to about 2 wt % based on the totalweight of the fluid, treatment fluid, or composition; in suchembodiments, the amount of the cellulose nanoparticles (alone, notcounting the cellulose fibers) in the fluids, treatment fluids, orcompositions of the present disclosure may be an amount of from about0.001 wt % to about 10 wt %, such as an amount of from about 0.01 wt %to about 10 wt %, or an amount of from about 0.1 wt % to about 5 wt %,or an amount of from about 0.5 wt % to about 2 wt % based on the totalweight of the fluid, treatment fluid, or composition.

Sand, gravel, glass beads, walnut shells, ceramic particles, sinteredbauxites, mica and other materials may be used as a proppant. Inembodiments, the mixture of cellulose fibers and cellulose nanoparticlesof the present disclosure may be used, such as in a fluid mixture, toassist in the transport proppant materials. In some embodiments, thefluids, treatment fluids, or compositions of the present disclosure maycomprise one or more the mixtures of cellulose fibers and cellulosenanoparticles for the above-mentioned proppant-related uses in an amountof from about 0.001 wt % to about 10 wt %, such as, about 0.01 wt % toabout 10 wt %, about 0.1 wt % to about 5 wt %, or of from about 0.5 wt %to about 5 wt % based on the total weight of the fluid, treatment fluid,or composition.

In some embodiments, the hydraulic fracturing fluids may be aqueoussolutions containing a thickener (or rheology modifier), such as asolvatable polysaccharide, a solvatable synthetic polymer, or aviscoelastic surfactant, that when dissolved in water or brine providessufficient viscosity to transport the proppant. Suitablethickeners/rheology modifiers may include polymers, such as guar(phytogeneous polysaccharide), and guar derivatives (hydroxypropyl guar,carboxymethylhydroxypropyl guar). Other synthetic polymers such aspolyacrylamide copolymers can be used also as thickeners. Water withguar represents a linear gel with a viscosity proportional to thepolymer concentration. Cross-linking agents are used which provideengagement between polymer chains to form sufficiently strong couplingsthat increase the gel viscosity and create visco-elasticity. Commoncrosslinking agents for guar and its derivatives and synthetic polymersinclude boron, titanium, zirconium, and aluminum. Another class ofnon-polymeric viscosifiers includes the use of viscoelastic surfactantsthat form elongated micelles. Known hydraulic fracturing fluids, may bemodified to incorporate a mixture of cellulose fibers and cellulosenanoparticles as a supplement to the thickener; or a mixture ofcellulose fibers and cellulose nanoparticles may be used as a substitutefor a conventional thickener, for example, a substitute for one or moreof the above mentioned thickeners.

Further, disclosed herein are methods and fluids (such as well treatmentfluids) for treating a subterranean formation in which a mixture ofcellulose fibers and cellulose nanoparticles of the present disclosuremay be used as additive to the polymer fluid to potentially increase theviscosity of the formulation by forming an entangled network between thecellulose fibers and cellulose nanoparticles and the polymer in solution(by generation of an increase in initial viscosity prior to the additionof a metallic crosslinker, such as, for example, boron, titanium,zirconium, and aluminum).

Fluids incorporating a mixture of cellulose fibers and cellulosenanoparticles of the present disclosure may have any suitable viscosity,such as a viscosity value of about 50 mPa·s or greater at a shear rateof about 100 s⁻¹ at treatment temperature, or about 75 mPa·s or greaterat a shear rate of about 100 s⁻¹ at the treatment temperature, or about100 mPa·s or greater at a shear rate of about 100 s⁻¹ at the treatmenttemperature, in some instances.

In some embodiments, an aqueous fracturing fluid comprising at least anaqueous base fluid, a proppant, a viscosifier/rheology modifier, amixture of cellulose fibers and cellulose nanoparticles of the presentdisclosure (for example, functioning as a flowback aid) and optionallyfurther components may be prepared using conventional equipment andtechniques. The components may be added in any order. The fluid may thenbe thoroughly mixed and a proppant is added. The specific composition ofthe aqueous fracturing fluid and the concentrations of the componentsused are chosen by the skilled artisan according to the intended resultsof the fracturing job.

The fracturing fluid may be pumped into a wellbore at a rate andpressure sufficient to flow into the formation and to initiate or extenda fracture in the formation. In order to initiate or to extend fracturesin the formation of a bottomhole, pressure sufficient to open a fracturein the formation may be used. The bottomhole pressure may be determinedby the surface pressure produced by the surface pumping equipment andthe hydrostatic pressure of the fluid column in the wellbore, less anypressure loss caused by friction. The minimum bottomhole pressure usedto initiate and/or to extend fractures may be determined by formationproperties and therefore may vary from application to application.Methods and equipment for fracturing procedures are known. Thefracturing fluid simultaneously transports suspended proppants and theproppant becomes deposited into the fractures and holds fractures openafter the pressure exerted on the fracturing fluid has been released.Thereafter, the applied pressure is reduced thereby allowing at least aportion of the injected fracturing fluid to flow back from the formationinto the wellbore. Reducing the pressure allows the fractures to close.Proppant “props” fractures open and fracturing fluid is shut in orallowed to flow back. At the surface, chokes may be used to generate apressure differential to allow fluid to begin to flow from the formationinto the well bore.

The mixture of cellulose fibers and cellulose nanoparticles of thepresent disclosure used in the fracturing fluid may facilitate theremoval of the fracturing fluid injected. The addition of the mixture ofcellulose fibers and cellulose nanoparticles of the present disclosureimproves the fluid recovery and improves regained permeability. In someembodiments, the percent regained permeability may be in a range of fromabout 15% to about 80%, such as in a range of from about 30% to about65%, or in a range of from about 40% to about 55%.

Thereafter, the aqueous fracturing fluid flowing back from the formationinto the wellbore may be removed from the wellbore. The total amount offluid recovered may depend on the formation, for instance on how muchwater the formation absorbs into its structure. The addition of themixture of cellulose fibers and cellulose nanoparticles of the presentdisclosure enhances the amount of fluid recovered compared to using afracturing fluid in which the mixture of cellulose fibers and cellulosenanoparticles of the present disclosure are not present.

Cementing

The mixture of cellulose fibers and cellulose nanoparticles may also beused as an additive in a cementing composition. Generally cementing awell includes pumping a cement slurry from the surface down the casingso that it then returns towards the surface via the annulus between thecasing and the borehole. One of the purposes of cementing a well is toisolate the different formation layers traversed by the well to preventfluid or gas migration between the different geological layers orbetween the layers and the surface. For safety reasons, prevention ofany gas rising through the annulus between the borehole wall and thecasing is desirable.

When the cement has set, it is impermeable to gas. Because of thehydraulic pressure of the height of the cement column, the injectedslurry is also capable of preventing such migration. However, there is aphase, between these two states which could last several hours duringwhich the cement slurry no longer behaves as a liquid but also does notyet behave as an impermeable solid. For this reason, additives, such asthose described in U.S. Pat. Nos. 4,537,918, 6,235,809 and 8,020,618,the disclosures of which are incorporated by reference herein theirentirety, may be added to maintain a gas-tight seal during the wholecement setting period.

The concept of fluid loss is also observed in cement slurries. Fluidloss occurs when the cement slurry comes into contact with a highlyporous or fissured formation. Fluid from the cement slurry will migrateinto the formation altering the properties of the slurry. When fluidloss occurs it makes the cement harden faster than it is supposed to,which could lead to incomplete placement. Fluid loss control additives(such as, for example, substituted glycine, FLAC, crosslinked PVA, HEC,and AMPS/acrylamide copolymer) may be used to prevent or at least limitthe fluid loss that may be sustained by the cement slurry duringplacement and its setting.

A variety of hydraulic cements can be utilized in accordance with thepresent application including, for example, Portland cements, slagcements, silica cements, pozzolana cements and aluminous cements.Specific examples of Portland cements include Classes A, B, C, G and H.

In embodiments, the fluids, treatment fluids, or compositions of thepresent disclosure may contain a foaming and/or stabilizing additivecomprising a mixture of cellulose fibers and cellulose nanoparticles,the mixture of cellulose fibers and cellulose nanoparticles beingpresent in an amount of from about 5 wt % to about 70 wt %, of fromabout 10 wt % to about 60 wt %, of from about 20 wt % to about 50 wt %,or of from about 30 wt % to about 40 wt % based on the total weight ofthe fluid, treatment fluid, or composition. In some embodiments, thefluids, treatment fluids, or compositions of the present disclosure maycontain a foaming and/or stabilizing additive comprising a mixture ofcellulose fibers and cellulose nanoparticles, the mixture of cellulosefibers and cellulose nanoparticles being present in an amount of fromabout 0.001 wt % to about 10 wt %, such as, about 0.01 wt % to about 10wt %, about 0.1 wt % to about 5 wt %, or of from about 0.5 wt % to about5 wt % based on the total weight of the fluid, treatment fluid, orcomposition.

The mixture of cellulose fibers and cellulose nanoparticles may act as abinder or surface activating agent for various cement composites andpotentially increase the affinity between the two different phases inthe cement composites. Therefore, in addition to reinforcing set cementprepared based on conventional formulations, the presence of the mixtureof cellulose fibers and cellulose nanoparticles may allow componentswith sharply-contrasting properties to co-exist in the compositeformulations. For instance, hydrophobic monomers like styrene can now bemixed with slurries and cured to form new types of cement composites.

According to the present disclosure, the slurry cement composition forcementing a well may comprise a hydraulic cement, water, a mixture ofcellulose fibers and cellulose nanoparticles and graphite. Graphite maybe used as a coarse particulate graphite average diameter is around 70to 500 μm for the particle size.

Portland cement containing carbon fiber and particulate graphitedemonstrates reduced cement resistivity values, when compared to theresistivity values of conventional cement with no fibers or graphitepresent. Small concentrations of carbon fiber provide a connective paththrough the cement matrix for electrons to flow.

Other additives may be present in the blend, such as fillers, retarders,fluid loss prevention agents, dispersants, rheology modifiers and thelike. In one embodiment, the blend also includes a polyvinyl alcoholfluid loss additive (0.1% to 1.6%) by weight of blend (“BWOB”),polysulfonate dispersant (0.5-1.5% BWOB), carbon black conductive filleraid not exceeding 1.0% BWOB, and various retarders (lignosulfonate,short-chain purified sugars with terminal carboxylate groups, and otherproprietary synthetic retarder additives). In another embodiment, theblend also includes a PVA containing fluid loss additive (0.2-0.3% byweight of blend (“BWOB”), polysulfonate dispersant (0.5-1.5% BWOB),carbon black conductive filler aid not exceeding 1.0% BWOB, and variousretarders (lignosulfonate, short-chain purified sugars with terminalcarboxylate groups, and other proprietary synthetic retarder additives).In some formulations, silica or other weighting additives, such ashematite or barite, may be used to optimize density of the cementcomposite slurry during placement across the zone of interest. Anysuitable silica concentrations may be used. In some embodiments, thesilica concentrations may not exceed 40% BWOC (by weight of cement).This is done to prevent strength retrogression when well temperaturesmay exceed 230° F. For most formulations, hematite or barite does notexceed 25% BWOB or BWOC.

In embodiments, the fluids, treatment fluids, or compositions of thepresent disclosure may contain a mixture of cellulose fibers andcellulose nanoparticles, the mixture of cellulose fibers and cellulosenanoparticles being present in an amount of from about 5 wt % to about70 wt %, of from about 10 wt % to about 60 wt %, of from about 20 wt %to about 50 wt %, or of from about 30 wt % to about 40 wt % based on thetotal weight of the fluid, treatment fluid, or composition. In someembodiments, the fluids, treatment fluids, or compositions of thepresent disclosure may contain a mixture of cellulose fibers andcellulose nanoparticles being present in an amount of from about 0.001wt % to about 10 wt %, such as, about 0.01 wt % to about 10 wt %, about0.1 wt % to about 5 wt %, or of from about 0.5 wt % to about 5 wt %based on the total weight of the fluid, treatment fluid, or composition.

In some embodiments, the amount of the cellulose fibers (alone, notcounting the cellulose nanoparticles) in the fluids, treatment fluids,or compositions of the present disclosure may be an amount of from about0.001 wt % to about 10 wt %, such as an amount of from about 0.01 wt %to about 10 wt %, or an amount of from about 0.1 wt % to about 5 wt %,or an amount of from about 0.5 wt % to about 2 wt % based on the totalweight of the fluid, treatment fluid, or composition; in suchembodiments, the amount of the cellulose nanoparticles (alone, notcounting the cellulose fibers) in the fluids, treatment fluids, orcompositions of the present disclosure may be an amount of from about0.001 wt % to about 10 wt %, such as an amount of from about 0.01 wt %to about 10 wt %, or an amount of from about 0.1 wt % to about 5 wt %,or an amount of from about 0.5 wt % to about 2 wt % based on the totalweight of the fluid, treatment fluid, or composition.

Fracture Plugging

Fractures in reservoirs normally have the highest flow capacity of anyportion of the reservoir formation. These fractures in the formation maybe natural or hydraulically generated. In a natural fault in the rockstructure, the high flow capacity results either from the same factorsas for natural fractures or from the fracture being open for example dueto natural asperities or because the rock is hard and the closure stressis low. In artificially created fractures, such as those created byhydraulic fracturing or acid fracturing, the high flow capacity resultsfrom the fracture being either propped with a very permeable bed ofmaterial or etched along the fracture face with acid or other materialthat has dissolved part of the formation.

Fractures of interest in this field may be connected to the subterraneanformation and/or to the wellbore. Large volumes of fluids will travelthrough fractures due to their high flow capacity. This allows wells tohave high fluid rates for production or injection. Normally, this isdesirable.

However, in the course of creating or using an oil or gas well, it isoften desirable to plug or partially plug a fracture in the rockformations, thereby reducing its flow capacity. Reasons for pluggingthese fractures may include a) they are producing unwanted water or gas,b) there is non-uniformity of injected fluid (such as water or CO₂) inan enhanced recovery flood, or c) expensive materials (such as hydraulicfracturing fluids during fracturing) are being injected intonon-producing areas of the formation. This latter case can beparticularly deleterious if it results in undesirable fracture growthbecause it wastes manpower, hydraulic horsepower, and materials, toproduce a fracture where it is not wanted, and at worst it results inthe growth of a fracture into a region from which undesirable fluids,such as water, are produced.

In embodiments, after well treatment composition is placed in thewellbore or the subterranean formation, at least one plug may be formedin at least one of a perforation, a fracture or the wellbore. The atleast one plug is comprised of at least a mixture of cellulose fibersand cellulose nanoparticles of the well treatment composition, and maybe installed for diversion and/or the isolation of various zones in thewellbore or the subterranean formation. Also, after the placement, thefracture may close on the mixture of cellulose fibers and cellulosenanoparticles after the well treatment composition is introduced intothe fracture. Furthermore, the plug may be plurality of plugs, thusisolating one or more regions within the subterranean formation orwellbore.

To prevent particle separation and uneven packing during mixing andinjection of the mixture of cellulose fibers and cellulosenanoparticles, the densities of the particulates (such as proppants),cellulose fibers and cellulose nanoparticles should be within about 20%of one another other. Particles are mixed and pumped using equipment andprocedures commonly used in the oilfield for cementing, hydraulicfracturing, drilling, and acidizing. These particles may be pre-mixed ormixed on site. They are generally mixed and pumped as a slurry in acarrier fluid such as water, oil, viscosified water, viscosified oil,and slick water (water containing a small amount of polymer that servesprimarily as a friction reducer rather than primarily as a viscosifier).In embodiments, the well treatment composition may also comprise acarrier fluid that is not capable of dissolving or disintegrating thecellulose fibers and cellulose nanoparticles.

Unless the particles have a very low density, and/or the carrier fluidhas a very high density, and/or the pump rate is very high, the carrierfluid will normally be viscosified in order to help suspend theparticles. Any method of viscosifying the carrier fluid may be used.Water may be viscosified with a non-crosslinked or a crosslinkedpolymer. The polymer, especially if it is crosslinked, may remain and beconcentrated in the fracture after the treatment and help impede fluidflow. In fracturing, polymers may be crosslinked to increase viscositywith a minimum of polymer. In embodiments, the more polymer may bebetter than less, unless cost prevents it, and crosslinking adds costand complexity, so uncrosslinked fluids can be also desirable, bearingin mind that more viscous fluids tend to widen fractures, which may beundesirable.)

In fracturing, it is desirable for the polymer to decompose after thetreatment, so the least thermally stable polymer that will survive longenough to place the proppant is often chosen. In embodiments, stablepolymers, such as polyacrylamides, substituted polyacrylamides, andothers may be advantageous. The choice of polymer, its concentration,and crosslinker, if any, is made by balancing these factors foreffectiveness, taking cost, expediency, and simplicity into account

Placement of the mixture of cellulose fibers and cellulose nanoparticlesplugging material is similar to the placement of proppant in hydraulicfracturing. The plugging material may be suspended in a carrier fluid toform a “filling slurry”. If a fracture is being created and plugged atthe same time, a “Property3D” (P3D) hydraulic fracture simulator may beused to design the fracture job and simulate the final fracture geometryand filling material placement. (If an existing fracture is beingplugged, a simulator is not normally used.) Examples of such a P3Dsimulator are FRACADE (Schlumberger proprietary fracture design,prediction and treatment-monitoring software), FRACPRO sold by PinnacleTechnologies, Houston, Tex., USA, and MFRAC from Meyer and Associates,Inc., USA. Whether a fracture is being created and plugged in a singleoperation, or an existing fracture is being plugged, the fracture wallshould be covered top-to-bottom and end-to-end (“length and height”)with filling slurry where the unwanted fluid flow is expected.Generally, the width of the created fracture is not completely filledwith the well treatment composition, but it may be desirable to ensurethat enough material is pumped to (i) at a minimum (should the fractureclose after placement of the well treatment composition) create a fulllayer of the largest (“coarse”) size material used across the entirelength and height of the region of the fracture where flow is to beimpeded, or to (ii) fill the fracture volume totally with well treatmentcomposition. When at least situation (i) has been achieved, the fracturewill be said to be filled with at least a monolayer of coarse particles.

The normal maximum concentration utilized may be three layers (betweenthe faces of the fracture) of the coarse material. If the fracture iswider than this, but will close, three layers of the filling materialmay be used, provided that after the fracture closes the entire lengthand height of the fracture walls are covered. If the fracture is widerthan this, and the fracture will not subsequently close, then either (i)more filling material may be pumped to fill the fracture, or (ii) someother material may be used to fill the fracture, such as for example,the malleable material described above. More than three layers may bewasteful of particulate material, may allow for a greater opportunity ofinadvertent undesirable voids in the particle pack, and may allowflowback of particulate material into the wellbore. Therefore,especially if the fracture volume filled-width is three times thelargest particle size or greater, then a malleable bridging material maybe added to reduce the flow of particles into the wellbore. This shouldbe a material that does not increase the porosity of the pack onclosure. Malleable polymeric or organic fibers are products thateffectively accomplish this. Concentrations of up to about 9.6 gmalleable bridging material per liter of carrier fluid may be used.

The carrier fluid may be any conventional fracturing fluid that willallow for material transport to entirely cover the fracture, will stayin the fracture, and will maintain the material in suspension while thefracture closes. Crosslinked guars or other polysaccharides may be used.Examples of suitable materials include crosslinked polyacrylamide orcrosslinked polyacrylamides with additional groups such as AMPS toimpart even greater chemical and thermal stability. Such materials may(1) concentrate in the fracture, (2) resist degradation, and provideadditional fluid flow resistance in the pore volume not filled byparticles. Additionally, wall-building materials, such as fluid lossadditives, may be used to further impede flow from the formation intothe fracture. Wall-building materials such as starch, mica, andcarbonates are well known.

Often it is desirable to plug a portion of the fracture; this occurs inparticular when the fracture is growing out of the desired region into aregion in which a fracture through which fluid can flow is undesirable.This can be achieved using the well treatment composition describedabove if the area to be plugged is at the top or at the bottom of thefracture. There are two techniques to achieve this; each may be usedwith either a cased/perforated completion or an open hole completion. Inthe first (“specific gravity”) technique the bridging slurry is pumpedbefore pumping of the main fracture slurry and has a specific gravitydifferent from that of the main fracture slurry. If the filling slurryis heavier than the main fracture slurry, then the plugged portion ofthe fracture will be at the bottom of the fracture. If the fillingslurry is lighter than the main fracture slurry, then the pluggedportion of the fracture will be at the top of the fracture. The fillingslurry will be inherently lighter or heavier than the proppant slurrysimply because the particles are lighter or heavier than the proppant;the difference may be enhanced by also changing the specific gravity ofthe carrier fluid for the particles relative to the specific gravity ofthe carrier fluid for the proppant.

The second (“placement”) technique is to run tubing into the wellbore toa point above or below the perforations. If the aim is to plug thebottom of the fracture, then the tubing is run in to a point below theperforations, and the bridging slurry is pumped down the tubing whilethe primary fracture treatment slurry is being pumped down the annulusbetween the tubing and the casing. This forces the filling slurry intothe lower portion of the fracture. If the aim is to plug the top of thefracture, then the tubing is run into the wellbore to a point above theperforations. Then, when the filling slurry is pumped down the tubingwhile the primary fracture treatment slurry is being pumped down theannulus between the tubing and the casing, the filling slurry is forcedinto the upper portion of the fracture. The tubing may be moved duringthis operation to aid placement of the particles across the entireundesired portion of the fracture. Coiled tubing may be used in theplacement technique.

In embodiments, the fluids, treatment fluids, or compositions of thepresent disclosure may contain a mixture of cellulose fibers andcellulose nanoparticles (for forming plugs) in an amount of from about 5wt % to about 70 wt %, of from about 10 wt % to about 60 wt %, of fromabout 20 wt % to about 50 wt %, or of from about 30 wt % to about 40 wt% based on the total weight of the fluid, treatment fluid, orcomposition. In some embodiments, the fluids, treatment fluids, orcompositions of the present disclosure may contain a mixture ofcellulose fibers and cellulose nanoparticles (for forming plugs) in anamount of from about 0.001 wt % to about 10 wt %, such as, about 0.01 wt% to about 10 wt %, about 0.1 wt % to about 5 wt %, or of from about 0.5wt % to about 5 wt % based on the total weight of the fluid, treatmentfluid, or composition.

In some embodiments, the amount of the cellulose fibers (alone, notcounting the cellulose nanoparticles) in the fluids, treatment fluids,or compositions of the present disclosure may be an amount of from about0.001 wt % to about 10 wt %, such as an amount of from about 0.01 wt %to about 10 wt %, or an amount of from about 0.1 wt % to about 5 wt %,or an amount of from about 0.5 wt % to about 2 wt % based on the totalweight of the fluid, treatment fluid, or composition; in suchembodiments, the amount of the cellulose nanoparticles (alone, notcounting the cellulose fibers) in the fluids, treatment fluids, orcompositions of the present disclosure may be an amount of from about0.001 wt % to about 10 wt %, such as an amount of from about 0.01 wt %to about 10 wt %, or an amount of from about 0.1 wt % to about 5 wt %,or an amount of from about 0.5 wt % to about 2 wt % based on the totalweight of the fluid, treatment fluid, or composition.

Gravel Packing

The mixture of cellulose fibers and cellulose nanoparticles of thepresent disclosure may be incorporated into a gravel packing fluid, suchas, for example, a gravel packing fluid used in conjunction with anassembly, a system, and a method for gravel packing. The gravel packingmethodology of the present disclosure may include a fluid and/ortreatment fluid comprising a cellulose fiber and a cellulosenanoparticle, such as a NCC particle, (for example, in theaforementioned amounts and/or ratios) but otherwise use conventionalgravel packing compositions/techniques known in the art, such as thosethat are described in U.S. Pat. Nos. 8,322,419 and 8,490,697, and U.S.Patent Application Publication Nos. 2015/0308238, 2015/0198016,2014/0014337, 2012/0048547, 2010/0096130, 2010/0314109, 20100018709,2010/0139919, 2008/0128129, and 2005/0028978, the disclosures of whichare incorporated by reference herein in their entireties.

In embodiments, a gravel packing fluid comprising a mixture of cellulosefibers and cellulose nanoparticles of the present disclosure may be usedin an alternate-path gravel packing procedure (such as described in theaforementioned patents and patent application publications, anddescribed below in more detail), and/or an alpha-beta wave procedure(such as described in the aforementioned patents and patent applicationpublications; for example, where a mixture of cellulose fibers andcellulose nanoparticles may be incorporated into one or more of thefluids, as desired, such as incorporated into one or more alpha/betawave water pack fluids (such as, for example, in a horizontal gravelpacking operations, to adjust the shear forces of the slurry fluid flowto adjust the equilibrium gravel height and/or the alpha waveprogression).

In some embodiments, a gravel packing fluid, which may comprise amixture of cellulose fibers and cellulose nanoparticles, may be pumpeddown a well system having a screen shunt tube configuration (forexample, an alternate-path gravel packing procedure). The shunt tubeconfiguration may provide an open path continuously along the length ofa screen. As the pumped gravel packing fluid passes through the shunttube(s) and reaches a point at which the system is not gravel packed,the pumped fluid may exit the shunt tube(s) and force its way into theincompletely packed volume to further pack the system. In someembodiments, the shunt tube(s) may provide a complete pack around ascreen by pumping a gravel packing fluid, which may comprise a mixtureof cellulose fibers and cellulose nanoparticles, down the shunt tubes tofill in any voids.

In some embodiments, the methods of the present disclosure may employalternate path gravel placement technology in conjunction withmultilateral junctions. Such methodology may be used to gravel pack inopen hole legs of a multilateral well in a manner that extends theapplication window of multilateral technologies while increasing thepotential for reducing field development related resources. For example,in some embodiments, a gravel packing fluid, which may comprise amixture of cellulose fibers and cellulose nanoparticles, may be pumpeddown one or more alternate paths created with shunts which have nozzlesand are disposed outside a gravel pack screen assembly. The one or moreshunts may provide an alternate pathway for a gravel slurry of thegravel packing fluid (which, if desired, may include a mixture ofcellulose fibers and cellulose nanoparticles), to bypass prematurebridging and to fill voids, thus resulting in a tight and completegravel pack in an uncased, e.g. open hole, lateral wellbore.

In some embodiments, gravel placement may initially proceed in astandard gravel packing mode until screen out. A pressure buildup mayoccur after screen out and force the gravel slurry of the gravel packingfluid (which, if desired, may include a mixture of cellulose fibers andcellulose nanoparticles) to flow through shunt tubes and to exit throughthe nozzles into the first available void. The gravel packing operationmay continue until the voids are filled and a final screen out occurs.By providing a mechanism able to eliminate voids in the gravel, thefinal gravel pack may be substantially improved.

In some embodiments, a lateral wellbore completion apparatus may beprovided with a crossover device positioned inside the open hole sectionof the lateral wellbore. The slurry (which, if desired, may include amixture of cellulose fibers and cellulose nanoparticles) may be directlyintroduced into the shunt tubes from a service tool via the crossoverdevice, and the slurry may be allowed to enter the open hole annulusfrom the shunt tubes alone, if desired. With this approach, no pressurebuildup external to the gravel pack assembly may be employed to forcethe gravel pack slurry along the shunt tubes. Instead, the pressureemployed to force the slurry through the shunt tubes is maintainedwithin the service tool and screen assembly. Additionally, the crossoverdevice and shunt tubes protect the open wellbore wall from contact withthe slurry in a destructive manner. Effectively, the equipment preventsuncontrolled flow of slurry against the surrounding formation of theopen wellbore, thus preventing degradation and/or collapse of thelateral wellbore.

In some embodiments, a gravel packing system of the present disclosuremay be deployed in a wellbore (such as a lateral wellbore) of a well,such as a multilateral well. In embodiments, the system of the presentdisclosure may be a gravel packing system as described in U.S. Pat. No.8,490,697, the disclosure of which is herein incorporated by referencein its entirety. Briefly, such as system may comprise a lateral wellborecompletion apparatus, which is used to establish a uniform, reliablegravel pack in an annulus surrounding at least a portion of the lateralwellbore completion. The lateral wellbore may be an upper lateralwellbore of a multilateral well.

In some embodiments, the lateral wellbore completion may comprise avariety of known components designed to facilitate application of theuniform gravel pack without voids in an open lateral wellbore. Forexample, wellbore completion may comprise an open hole packer that maybe expanded against a surrounding wall of open hole lateral wellbore toisolate an annulus. Wellbore completion may also comprise a screensection formed of one or more individual screens disposed in the regionto receive gravel pack. Between the open hole packer and the screensection, various known components may be positioned to facilitatecreation of the alternate path for directing a gravel slurry, which mayinclude a mixture of cellulose fibers and cellulose nanoparticles.

For example, a crossover system may be employed to direct slurry from aninterior of a lateral wellbore completion to an alternate path systemand ultimately into the surrounding annulus. The crossover system may beconstructed in a variety of known forms, for example, in someembodiments, the crossover system may comprise a shrouded circulatinghousing. The shrouded circulating housing may comprise a shroud and aflow control device, such as a port closure sleeve mechanism. Thesliding sleeve mechanism may be controlled to selectively allow flow ofgravel slurry from an interior flow area of lateral wellbore completioninto the shroud. From the interior of the shroud, the gravel slurry,which may include a mixture of cellulose fibers and cellulosenanoparticles, may flow into any suitable alternate path system, forexample, an alternate path system as described in U.S. Pat. No.8,490,697, the disclosure of which is herein incorporated by referencein its entirety, for uniform distribution along annulus around screensection.

For example, a suitable alternate path system may comprise one or moreshunt tubes that are coupled to shroud of shrouded circulating housing.The shunt tubes may be designed to deliver the gravel slurry to thedesired gravel pack region by providing a shunted space out tubingsection and a shunted blank section with nozzles. Other components oflateral wellbore completion may comprise a polished bore receptaclepositioned adjacent the shrouded circulating housing to receive a gravelpack service tool which may be selectively moved into the wellborecompletion to deliver the gravel slurry, which may include a mixture ofcellulose fibers and cellulose nanoparticles. A blank pipe section maybe disposed between the open hole packer and the polished borereceptacle. Additionally, a large bore flapper valve, or anothersuitable valve, may be positioned in the interior flow area of wellborecompletion between the shroud and screen section. The large bore flappervalve may be selectively activated to control the flow of fluid alongthe interior flow area. For example, the flapper valve may be used tofacilitate flow of gravel slurry (which may include a mixture ofcellulose fibers and cellulose nanoparticles) into the shunt tubes.

In some embodiments, additional components may be incorporated intolateral wellbore completion depending on the parameters of a givengravel packing operation and the environment in which the gravel pack isformed. For example, in some embodiments, the design of lateral wellborecompletion may by selected to enable the gravel slurry (which mayinclude a mixture of cellulose fibers and cellulose nanoparticles) to beforced into the desired gravel pack area through the alternate pathsystem without application of pressure to a surrounding formation.

In some embodiments, the components (and concentration thereof) of thegravel packing fluid may be selected such that the mixture suspends thegravel as the fluid travels through the shunts and into the wellbore,even at high temperatures, such as temperatures in excess of about 180°F. (such as temperatures in the range of about 180° F. to about 280° F.,or temperatures in the range of about 180° F. to about 240° F.), withoutserious thinning. For example, the components of the gravel packingfluid may be selected to include an amount of a mixture of cellulosefibers and cellulose nanoparticles effective to suspend the gravel inthe fluid at high temperatures, such as temperatures in excess of about180° F. (such as temperatures in the range of about 180° F. to about280° F., or temperatures in the range of about 180° F. to about 240°F.), without serious thinning, such that the gravel does not deposit inthe shunt tubes. Otherwise, the gravel would have a tendency to depositin the shunt tubes during a shut in and/or at high temperatures (such asthose described above) causing the shunt tubes to be packed closedbefore the gravel pack in the wellbore is complete. This may result invoids in the gravel pack and reduce the effectiveness of the gravel packto control production of formation sands.

In some embodiments, a packer may be positioned and set in a casingabove the sand screen to isolate the interval being packed. A crossoverservice tool may also be provided with an assembly to selectively allowfluids to flow between the annulus formed by the open hole and thescreen assembly and the interior of a tubular member and a wash pipe.With the sand control screen assembly in place, a gravel packing fluid,such as a gravel packing fluid containing gravel (and optionally amixture of cellulose fibers and cellulose nanoparticles) for forming thegravel pack and a water-based carrier fluid may be introduced into thewellbore to facilitate gravel packing of the open hole section of thewellbore in the annulus surrounding the sand control screen. The gravelpacking fluid may be introduced into a tubular member where it flows tothe cross over tool into the annulus of the open hole section below thepacker and the exterior of the sand control screen. As the gravel (andthe optional mixture of cellulose fibers and cellulose nanoparticles, ifselected such that it will effectively settle with the gravel) settleswithin the open hole section surrounding the screen, a carrier fluid ofthe gravel packing fluid may pass through the screen and into theinterior of the tubular member. The carrier fluid may be conducted tothe crossover tool and into the annulus between the casing and thetubular member above the packer. In some embodiments, the cellulosefibers may be sized so that they will not pass through the screenopenings.

In some embodiments, the gravel particles may be ceramics, natural sandor other particulate materials suitable for such purposes. The gravelparticles may be sized so that they will not pass through the screenopenings. Suitable particle sizes in U.S. mesh size may range from about12 mesh (1.68 mm) to about 70 mesh (0.210 mm). A combination ofdifferent particle sizes may be used. Examples of typical particle sizecombinations for the gravel particles may about 12/20 mesh (1.68mm/0.841 mm), 16/20 mesh (1.19 mm/0.841 mm), 16/30 mesh (1.19 mm/0.595mm), 20/40 mesh (0.841 mm/0.420 mm), 30/50 mesh (0.595 mm/0.297 mm),40/60 mesh (0.420 mm/0.250 mm) and 40/70 mesh (0.420 mm/0.210 mm). Thegravel particles may be coated with a resin to facilitate binding of theparticles together, and/or interaction with the mixture of cellulosefibers and cellulose nanoparticles.

The carrier fluid of the gravel packing fluid may be a water-based fluidor aqueous fluid, which may be composed of an aqueous brine or saltsolution. The carrier fluid may have any suitable density, such as afluid density in a range of from about 8.8 ppg (1.05 kg/L) to about 19.2ppg (2.3 kg/L), or from about 8.8 ppg (1.05 kg/L) to about 14.2 ppg(1.70 kg/L).

In some embodiments, the aqueous carrier fluid may also be viscosifiedwith a viscosifying agent (in addition to the mixture of cellulosefibers and cellulose nanoparticles, if present in the aqueous carrierfluid). The amount and type of viscosifying agent is selected to providethe desired carrying effect for the gravel particles and to ensureefficient return of the carrier fluid. The viscosifying agents mayinclude those described in U.S. Patent Application Publication No.2009/0065207, the disclosure of which is herein incorporated byreference in its entirety.

In some embodiments, the viscosifying agent may be present in an amountof from about 0.1 wt. % to about 1.5 wt. % of total weight of thecarrier fluid, from about 0.1 wt. % to about 0.7 wt. % of total weightof carrier fluid, from about 0.1 wt. % to about 0.6 wt. % of totalweight of carrier fluid, from about 0.1 wt. % to about 0.5 wt. % oftotal weight of carrier fluid, from about 0.1 wt. % to about 0.4 wt. %total weight of carrier fluid, from about 0.1 wt. % to about 0.3 wt. %of total weight of carrier fluid, or even from about 0.1 wt. % to about0.2 wt. % of total weight of carrier fluid. In some embodiments, aviscoelastic surfactant (VES) may be used as a viscosifying agent forthe carrier fluid. The VES may be selected from the group consisting ofcationic, anionic, zwitterionic, amphoteric, nonionic, and combinationsof these, such as those described in U.S. Pat. Nos. 6,435,277 and6,703,352 the disclosures of which are incorporated by reference hereinin their entireties.

In embodiments, the gravel packing fluids, treatment fluids, orcompositions of the present disclosure may contain any desired amount ofa mixture of cellulose fibers and cellulose nanoparticles to accomplishthe intended down hole operation. In some embodiment, the mixture ofcellulose fibers and cellulose nanoparticles may be present in an amountof from about 5 wt % to about 70 wt %, of from about 10 wt % to about 60wt %, of from about 20 wt % to about 50 wt %, or of from about 30 wt %to about 40 wt % based on the total weight of the gravel packing fluid,treatment fluid, or composition. In some embodiments, the gravel packingfluids, treatment fluids, or compositions of the present disclosure maycontain a mixture of cellulose fibers and cellulose nanoparticles beingpresent in an amount of from about 0.001 wt % to about 10 wt %, such as,about 0.01 wt % to about 10 wt %, about 0.1 wt % to about 5 wt %, or offrom about 0.5 wt % to about 5 wt % based on the total weight of thegravel packing fluid, treatment fluid, or composition.

In some embodiments, the gravel packing fluids, treatment fluids, orcompositions of the present disclosure may comprise a mixture ofcellulose fibers and cellulose nanoparticles (such as NCC) in anydesired ratio, such as ratio in the range of from about 0.6:1 to about1:0.6 (wt % cellulose fibers:wt % cellulose nanoparticles, such as NCC),such as in a ratio in a range of from about 0.8:1 to about 1:0.8 (wt %cellulose fibers:wt % cellulose nanoparticles, such as NCC), and or aratio of about 1:1 (wt % cellulose fibers:wt % cellulose nanoparticles,such as NCC).

In some embodiments, the amount of the cellulose fibers (alone, notcounting the cellulose nanoparticles) in the gravel packing fluids,treatment fluids, or compositions of the present disclosure may be anamount of from about 0.001 wt % to about 10 wt %, such as an amount offrom about 0.01 wt % to about 10 wt %, or an amount of from about 0.1 wt% to about 5 wt %, or an amount of from about 0.5 wt % to about 2 wt %based on the total weight of the gravel packing fluid, treatment fluid,or composition; in such embodiments, the amount of the cellulosenanoparticles (alone, not counting the cellulose fibers) in the gravelpacking fluids, treatment fluids, or compositions of the presentdisclosure may be an amount of from about 0.001 wt % to about 10 wt %,such as an amount of from about 0.01 wt % to about 10 wt %, or an amountof from about 0.1 wt % to about 5 wt %, or an amount of from about 0.5wt % to about 2 wt % based on the total weight of the gravel packingfluid, treatment fluid, or composition.

The foregoing is further illustrated by reference to the followingexamples, which are presented for purposes of illustration and are notintended to limit the scope of the present disclosure.

EXAMPLES

Example 1: The following settling test experiments were carried out at250° F. for 30 minutes to demonstrate how a combination of cellulosefibers and cellulose nanoparticles achieves improved suspensioncapability over formulations in which a combination of cellulose fibersand cellulose nanoparticles is absent.

A base fluid composition common for each of the fluids studied wasprepared: The base fluid containing a viscoelastic surfactant (VES) 6%(by volume); CaCl₂)/CaBr₂ (10.6 ppg); a brine solution (1.4039 g/mLdensity); and a proppant (Carbolite 20/40 Mesh at a concentration of 4ppa). For the cellulose nanoparticles, NCC rod shaped materials having alength of about 92 nm and diameter of about 6 nm were used. For thecellulose fibers, cellulose fibers having a length in a range of fromabout 100 to 200 microns and diameter in a range of from about 10 toabout 40 microns were used.

In the tests the base fluid was combined with the respective amounts ofcellulose fibers and/or cellulose nanoparticles, as identified in thetable below. Then the settling test experiments were carried out at 250°F. for 30 minutes and inspected visually. The results of the test areshown in the table below.

Cellulose Cellulose % Sand Nanoparticles Fibers that Test Fluid (wt %)(wt %) Settled Experiment 1 0.25 wt % 0 wt % 100% Experiment 2 0 wt %0.25 wt % 100% Experiment 3 0.25 wt % 0.25 wt %  0% Experiment 4 0 wt %0.5 wt % 100% Experiment 5 0.5 wt % 0 wt %  0% Experiment 8 0.375 wt %0.125 wt %  0%

Neither the cellulose nanoparticles nor the cellulose fibers (when usedat an amount of 0.25 weight percent) were able to suspend the proppant.However, when the cellulose nanoparticles and the cellulose fibers wereadded together the mixture shows excellent suspension capability, whichmay result from a type of synergy between the two components (that is,the combination of the cellulose nanoparticles and the cellulose fiberscreates a type of synergy).

Example 2: The following test demonstrates that cellulose nanoparticles(the same as those used above) help the cellulose fibers to suspend insolution.

A solution of 0.25 wt % of cellulose fibers (the same as those usedabove) in water was prepared and the cellulose fibers would fall to thebottom of the container. When this solution was passed through a 200micron screen, a white filter cake was formed, as depicted in FIG. 1.

However, when the cellulose fibers were mixed with cellulosenanoparticles (the same as those used above) at a ratio of 1/1, thefibers were suspended and no filter cake was formed, as depicted in FIG.2.

Example 3: Regained permeability tests

The core regained permeability tests were performed on a FormationResponse Tester equipment. The cellulose nanoparticles and cellulosefibers used were the same as those described above.

The regained permeability tests were performed on Aloxite and sandstonescores, Bentheimer (1200-1600 mD) sandstones cores which are shown inFIG. 3.

The sandstone cores were analyzed by mercury injection capillarypressure tests. Results of the pores size distribution of the differentsamples are highlighted in the table below.

Parameter Mercury Inj. Median Pore Nanopores (1 nm < Micropores (1 μm <Mesopores (62.5 μm < Example Porosity Throat Size Diameter > 1 μm)Diameter > 62.5 μm) Diameter > 4 mm) Name (fraction) (μm) (% PV) (% PV)(%PV) Bentheimer 1 0.23 35.5 3.36 96.3 0.319 Bentheimer 2 0.20 34.5 2.9497.1 0.00 Parameter Mercury/Air Air/Brine Swanson Example Entry PressureEntry Pressure Permeability Name (psi) (psi) (mD) Bentheimer 1 3.170.731 1691 Bentheimer 2 3.81 0.879 1299

Both samples have a large portion of pores in the micropore regionsranging from 1 to 62.5 μm.

The regained permeability tests were carried out using 6 inch bentheimercores of permeability close to 1.2D and formulation containing 6% VESand various concentrations (see the table below) of cellulose fiberswere mixed with cellulose nanoparticles.

In order to arrive at the regained permeability data provided in thetable below, the following methodology was used with the equipmentillustrated above: 1) obtain 6″ core and record the initial weight anddimensions; 2) saturate the core in 2% KCl for 20 minutes and remove itfrom the solution and record its saturated weight, and calculate “PV”(Pore volume of the core); 3) load the 6″ core followed by 6″ spacer(total length 12; 4) apply 2500 psi confining pressure and heat the cellto a predetermined temperature; 5) flow 2% KCl at 5 milliliters/minute(mL/min) and 20 mL/min in production to get an initial permeabilityvalue at those flow rates; 6) flow the treatment fluid at 2 ml/mininjection direction until max pressure was reached (1800 psi); and 7)flow 2% KCl at 20 mL/min for about 100 PV in production direction andmeasure the regained permeability at 20 mL/min and 5 ml/min.

The results of the regained permeability tests for a formulationcontaining 6% VES and various concentrations of cellulose fibers and/orcellulose nanoparticles are shown in the table below.

Percent Regained Test Fluid permeability Experiment 6 VES + 0.5%Cellulose 8 Nanoparticles Experiment 7 VES + 0.5% (Cellulose 65Nanoparticles/Cellulose Fibers: 50/50) Experiment 8 VES + 0.5%(Cellulose 30 Nanoparticles/Cellulose Fibers:75/25)

The results of these experiments suggest that an increased percentregained permeability is achieved with a 1:1 weight ration of cellulosenanoparticles to cellulose fibers. By adjusting the concentration ratio,it is thus possible to control the regained permeability to the desiredlevels.

Although the preceding description has been described herein withreference to particular means, materials and embodiments, it is notintended to be limited to the particulars disclosed herein; rather, itextends to all functionally equivalent structures, methods and uses,such as are within the scope of the appended claims. In the claims,means-plus-function clauses are intended to cover the structuresdescribed herein as performing the recited function and not onlystructural equivalents, but also equivalent structures. Thus, although anail and a screw may not be structural equivalents in that a nailemploys a cylindrical surface to secure wooden parts together, whereas ascrew employs a helical surface, in the environment of fastening woodenparts, a nail and a screw may be equivalent structures. It is theexpress intention of the applicant not to invoke 35 U.S.C. § 112(f) forany limitations of any of the claims herein, except for those in whichthe claim expressly uses the words ‘means for’ together with anassociated function.

What is claimed is:
 1. A fluid for treating a subterranean formationcomprising: a solvent; a rheology modifier; and a composition comprisinga mixture of cellulose fibers and cellulose nanoparticles, wherein thecellulose nanoparticles have a positive zeta potential in a range ofabout +100 mV to about +10 mV, and a length in a range of from about 50nm to about 500 nm, and wherein the cellulose fibers have a length offrom about 50 microns to about 500 microns.
 2. The fluid for treatingthe subterranean formation of claim 1, wherein about 0.1 to about 2% byweight based on the total weight of the treatment fluid is the mixtureof cellulose nanoparticles and cellulose fibers.
 3. The fluid fortreating the subterranean formation of claim 1, wherein the cellulosefibers are present in an amount of from about 25% to about 50% by weightbased on the total weight of the mixture of cellulose nanoparticles andcellulose fibers.
 4. The fluid for treating the subterranean formationof claim 1, wherein the cellulose nanoparticles are present in an amountof from about 50% to about 75% by weight based on the total weight ofthe mixture of cellulose nanoparticles and cellulose fibers.
 5. Thefluid for treating the subterranean formation of claim 1, wherein atleast a portion of the cellulose nanoparticles have a negative zetapotential.
 6. The fluid for treating the subterranean formation of claim5, wherein the negative zeta potential is imparted by an anionicfunctional group that is present on the surface of the cellulosenanoparticles.
 7. The fluid for treating the subterranean formation ofclaim 5, wherein the negative zeta potential is in a range of from about−100 mV to about −10 mV.
 8. The fluid for treating the subterraneanformation of claim 1, wherein each of the cellulose nanoparticles havean outer surface having a percent surface functionalization of fromabout 5 to about 90 percent.
 9. The fluid for treating the subterraneanformation of claim 8, wherein the outer surface of each of cellulosenanoparticles comprises one or more member selected from the groupconsisting of sulfates, phosphates, amines, and carboxylates.
 10. Thefluid for treating the subterranean formation of claim 1, wherein atleast a portion of cellulose nanoparticles are a rod-likenanocrystalline cellulose particle (NCC particle) having a crystallinestructure.
 11. The fluid for treating the subterranean formation ofclaim 1, wherein the solvent is water or brine.
 12. The fluid fortreating the subterranean formation of claim 1, wherein the rheologymodifier is a polymer.
 13. The fluid for treating the subterraneanformation of claim 1, wherein the rheology modifier is a viscoelasticsurfactant.
 14. The fluid for treating the subterranean formation ofclaim 1, wherein the fluid is selected from the group consisting of afracturing fluid, well control fluid, well kill fluid, well cementingfluid, acid fracturing fluid, acid diverting fluid, a stimulation fluid,a sand control fluid, a completion fluid, a wellbore consolidationfluid, a remediation treatment fluid, a drilling fluid, a spacer fluid,a frac-packing fluid, water conformance fluid and gravel packing fluid.